Self-destructive barite filter cake in water-based and oil-based drilling fluids

ABSTRACT

Drilling fluid compositions may include a weighting agent, a nitrite-containing compound, and an ammonium-containing compound, where the nitrite-containing compound and the ammonium-containing compound may be encapsulated together in copolymer micro-particles forming encapsulated thermochemical compounds, and where at least one property selected from the group consisting of the density, the plastic viscosity, the yield point, the gel strength, and the pH, of the drilling fluid composition may be substantially similar to the at least one property of a comparable drilling fluid composition devoid of the encapsulated thermochemical compounds. Methods for reducing a filter cake from a wellbore surface in a subterranean formation are also provided. The methods may include introducing into the wellbore the drilling fluid compositions, allowing the drilling fluid composition to reach a temperature in the wellbore sufficient for the encapsulated thermochemical compounds to react, where the reaction of the encapsulated thermochemical compounds generates heat and nitrogen gas.

BACKGROUND

Drilling fluids are used to help drill wellbores into earth formations.Liquid drilling fluids may be water-based or oil-based. Drilling fluidsmay be used to cool the drilling equipment, reduce friction between thedrill bit and the wellbore surface, control the formation pressure, sealpermeable formations, and maintain wellbore stability. When drillingwellbores into permeable formations, oil-based or water-based drillingfluids may create a hydrostatic pressure, preventing fluids in theformations from penetrating the wellbore.

Drilling fluids may include a weighting material that forms a layer ofresidue or solid particles called “filter cake” or “mud cake”. This cakelines the surface of permeable wellbore zones to prevent both fluidsfrom the formation from leaking into the wellbore and drilling fluidfiltrate from penetrating into the formation.

Weighting materials are generally the main solid constituent of drillingfluids. Barite is often used to increase the weight and hydrostaticpressure of both oil-based and water-based drilling fluids. Inoperations using these types of drilling fluid, the resulting filtercake is mainly composed of barite particles. Such filter cake isimpermeable and highly insoluble in both water and acidic solutions,such as solutions of acetic acid, hydrochloric acid, and formic acid. Assuch, the cake controls drilling fluid loss and mitigates solidsinvasion in the formation, both of which may contribute to formationdamage.

SUMMARY

Certain embodiments of the disclosure will be described with referenceto the accompanying Drawings, where like reference numerals denote likeelements. It should be understood, however, that the accompanyingfigures illustrate the various implementations described and are notmeant to limit the scope of various technologies described.

In some embodiments, drilling fluid compositions are provided. Thedrilling fluid compositions may include a weighting agent, anitrite-containing compound, and an ammonium-containing compound. Thenitrite-containing compound and the ammonium-containing compound may beencapsulated together in copolymer micro-particles forming encapsulatedthermochemical compounds. At least one property selected from the groupconsisting of the density, the plastic viscosity, the yield point, thegel strength, and the pH of the drilling fluid composition may besubstantially similar to the at least one property of a comparabledrilling fluid composition devoid of the encapsulated thermochemicalcompounds.

In some embodiments, methods are provided for reducing a filter cakefrom a wellbore surface in a subterranean formation. The methods mayinclude introducing into the wellbore a drilling fluid compositioncomprising a weighting agent, a nitrite-containing compound, and anammonium-containing compound, where nitrite-containing compound and theammonium-containing compound are encapsulated together in copolymermicro-particles forming encapsulated thermochemical compounds. Inaddition, the methods may include allowing the drilling fluidcomposition to reach a temperature in the wellbore sufficient for theencapsulated thermochemical compounds to react, where the reaction ofthe encapsulated thermochemical compounds generates heat and nitrogengas. Further, in the methods at least a portion of the formed filtercake is removed using the heat and nitrogen gas released from thereaction of the thermochemical compounds.

Other aspects and advantages of this disclosure will be apparent fromthe following Detailed Description made with reference to theaccompanying Drawings and the appended Claims.

BRIEF DESCRIPTION OF DRAWINGS

FIG. 1 is graph showing the effect of molar concentration ofthermochemical reactants on pressure pulse generation according to oneor more embodiments.

FIG. 2 is a bar graph showing the time required for thermochemicalreactants at different molar ratios to reach maximum temperature invarious reservoir temperatures according to one or more embodiments.

FIG. 3 is a schematic illustration of the high-pressure/high-temperature(HPHT) static filter press apparatus used in testing Experiments 1 and 2and Comparative Examples 1 and 2 according to one or more embodiments.

FIG. 4 is a bar graph showing the density, plastic viscosity, yieldpoint, 10 second (sec) gel strength, 10 minute (min) gel strength, andpH for Comparative Example 1 and Experiment 1 according to one or moreembodiments.

FIG. 5 is a bar graph showing the density, plastic viscosity, yieldpoint, 10 sec gel strength, 10 min gel strength, and pH for Experiment 2and Comparative Example 2 according to one or more embodiments.

FIG. 6 is a graph showing the filtrate volume in function of timeillustrating the filtration performances of the drilling fluids ofExperiment 1 and Comparative Example 1 according to one or moreembodiments.

FIG. 7 is a bar graph showing the filtrate volume in function of timeillustrating the filtration performances of the drilling fluids ofExperiments 2 and Comparative Example 2 according to one or moreembodiments.

FIG. 8 is a bar graph showing the filter cake thickness formed fromExperiments 1 and 2 and Comparative Examples 1 and 2 according to one ormore embodiments.

FIG. 9 shows the graphs of pressure and temperature of encapsulated andnon-encapsulated thermochemicals in function of time of Example 5according to one or more embodiments.

FIG. 10 shows the graphs of pressure and temperature of encapsulated andnon-encapsulated thermochemicals in function of time of Example 5according to one or more embodiments.

DETAILED DESCRIPTION

The formation of filter cake on the face of a permeable formationdepends on several parameters of drilling fluids, such as weightage ofsolid particles, composition, rheology, additives, differentialpressure, and formation mineralogy. In addition, filter cake properties,such as thickness, toughness, slickness, and permeability may affect thereservoir productivity. Filter cake formed on the surface of permeablewellbore zones may reduce reservoir productivity by blocking theproduction of oil and gas from permeable formations into the wellbore.Further, when cementing operations are undertaken to seal lostcirculation zones, the presence of filter cake may cause the debondingof cement between the casing and the formation. Therefore, the removalof filter cake during or after drilling operations is desirable.

Examples of materials that may be used to remove filter cake includeacids and enzymes. However, the simultaneous removal of filter cake andinhibition of formation damage in formations, such as carbonateformations, with acids is expensive and challenging. This is especiallytrue in horizontal wells because of both the fast reaction of the acidand the difficulty of placing the acid at an appropriate location inhorizontal sections. Further, enzymes have been shown to partiallydegrade in the presence of acids and oxidizers. Accordingly, thereexists a need for improved filter cake removal treatments to reduce oreliminate filter cake formed from the use of barite weighting agent indrilling fluids.

Generally, embodiments disclosed relate to drilling fluid compositionsand methods for reducing the amount of or eliminating filter cakeresulting from the use of treatment additives, such as weighting agents,in these drilling fluids. The one or more embodiments relate to bothoil-based and water-based drilling fluid compositions that includeencapsulated thermochemical compounds that reduce or eliminate thefilter cake.

One or more embodiments relate to drilling fluid compositions andmethods that remove filter cake from the surface of permeable wellborezones. The methods provide useful conditions for filter cake removaltreatments to be effective. The compositions include a weighting agent,such as barite, and encapsulated thermochemicals.

Barite is barium sulfate (BaSO₄). Barite increases the hydrostaticpressure of drilling fluids, which compensates for high-pressure zonesduring drilling to prevent fluid influx or even a blowout. Barite isalso used as lubricant, preventing the damage of drilling tools duringdrilling. In the formulations according to some embodiments, bariumsulfate is in the form of particles having a size in a range of about 40microns to about 60 microns.

As used, the term “thermochemicals” may also be referred to as“thermochemical compounds” or “thermochemical reactants,” and mayinclude chemicals that exothermically react to produce heat andpressure. Thermochemicals may be provided in a fluid solution (forexample, a diluted or concentrated solution containing one or more typesof thermochemicals), a suspension, or in a dry form (for example, apowder). In one or more embodiments, thermochemical compounds mayinclude, but are not limited to, urea, sodium hypochlorite,ammonium-containing compounds, or nitrite-containing compounds. Examplesof ammonium-containing compounds include ammonium chloride, ammoniumbromide, ammonium nitrate, ammonium sulfate, ammonium carbonate, andammonium hydroxide. Examples of nitrite-containing compounds includesodium nitrite and potassium nitrite.

In one or more embodiments, thermochemical compounds may include bothammonium-containing compounds and nitrite-containing compounds to act asthe encapsulated thermochemicals. For example, the ammonium-containingcompound may be ammonium chloride or ammonium sulfate; thenitrite-containing compound may be sodium nitrite. The thermochemicalreactions of ammonium chloride and sodium nitrite are represented byEquations (1) and (2), respectively:

$\begin{matrix}\left. {{{NH}_{4}{Cl}} + {NaNO}_{2}}\rightarrow\begin{bmatrix}{{{NH}_{4}{NO}_{2}} + {{{NaCl}.{NH}_{4}}{NO}_{2}}} \\{Themolabile}\end{bmatrix}\rightarrow{{NaCl} + {2H_{2}0} + {N_{2}({gas})} + {\Delta{H({heat})}}} \right. & (1)\end{matrix}$ $\begin{matrix}\left. {{\left( {NH}_{4} \right)2{SO}4} + {NaNO}_{2}}\rightarrow\begin{bmatrix}{{{NH}_{4}{NO}_{2}} + {{Na}2{SO}4.{NH}_{4}{NO}_{2}}} \\{Themolabile}\end{bmatrix}\rightarrow{{{Na}2{SO}4} + {2H_{2}0} + {2{N_{2}({gas})}} + {\Delta{H({heat})}}} \right. & (2)\end{matrix}$

According to the thermochemical reactions of Equations (1) and (2), thethermochemical compounds generate “thermolabile” intermediate products,which are immediately transformed into sodium chloride or sodium sulfate(salts), nitrogen (gas), and steam (water+heat). The release of nitrogengas and steam generates high pressure conditions. The use of ammoniumsulfate generates more pressure than the use of ammonium chloride inthermochemical reactions under the same conditions.

Two types of energy—kinetic energy and thermal energy—are associatedwith the reactions of the thermochemical compounds of the drilling fluidcompositions and corresponding methods. For example, in the reactionillustrated by Equation (1), ammonium chloride and sodium nitritesolutions are mixed in the presence of heat (for example, >150° F.) togenerate N₂ gas and heat. The pressure generated in the case of ammoniumchloride is about 1000 psi; about 2000 psi in the case of ammoniumsulfate.

The concentration of thermochemical reactants may be in a range of fromabout 0.5 to about 10 molar (M), such as from about 1 to about 5 M, suchas from about 1 to about 2 M. Greater concentrations generate increasedhigh-pressure conditions, as illustrated in FIG. 1 where there is a moleratio of 1:1. The molar solution ratio of the thermochemical compoundsmay vary, such as 1:1 or 2:2 for the molar solution ratio of ammoniumchloride to sodium nitrite. Greater molar ratios may lead to a reducedamount of time to reach maximum temperature, as shown in FIG. 2 .

In the drilling fluid compositions and methods to remove filter cakefrom the surface of permeable wellbore zones, the nitrite-containingcompound and the ammonium-containing compound may be encapsulatedtogether in copolymer micro-particles, forming encapsulatedthermochemical compounds.

The copolymer micro-particles encapsulate may include delayed releasecopolymers of esters or carbonic acid. Other delayed release copolymersmay include derivatives of formic acid, lactic acid, methyl lactate,ethyl lactate, propyl lactate, and butyl lactate. Other delayed releasecopolymers may include polyesters of glycerol, tripropionin (a triesterof propionic acid and glycerol), trilactin, and esters of acetic acidand glycerol, such as monoacetin, diacetin, and triacetin. Other delayedrelease copolymers may include ethylene glycol monoformate, ethyleneglycol diformate, diethylene glycol diformate, glyceryl monoformate,glyceryl diformate, glyceryl triformate, triethylene glycol diformateand formate esters of pentaerythritol. In one or more embodiments, thedelayed release copolymer micro-particles may include aliphaticpolyesters, poly(lactides), poly(glycolides), poly(caprolactones),poly(hydroxy ester ethers), poly(hydroxybutyrates), poly(anhydrides),aliphatic polycarbonates, poly(orthoesters), poly(amino acids),poly(ethylene oxides), and polyphosphazenes.

In one or more embodiments, the copolymer micro-particles encapsulatingthe thermochemical compounds may have a size in a range of from about 25to about 50 microns.

In the drilling fluid compositions and methods to remove filter cakefrom the surface of permeable wellbore zones, the properties of thedrilling fluid composition are substantially similar to thecorresponding property of a comparable drilling fluid composition devoidof encapsulated thermochemical compounds. In particular, physio-chemicalproperties, including the density, the plastic viscosity, the yieldpoint, the gel strength, and the pH of the drilling fluid compositioncontaining a nitrite-containing compound and an ammonium-containingcompound encapsulated together in copolymer micro-particles aresubstantially similar to the corresponding properties of the similardrilling fluid composition not containing encapsulated thermochemicalcompounds as illustrated in FIGS. 4 and 5 .

The drilling fluid compositions according to one or more embodiments arewater- or oil-based, such as diesel, and may include emulsions havingboth water and oil. Further, the drilling fluid compositions may includeone or more additives, such as a rheology modifier, a pH-adjuster, aclay stabilizer, a bridging agent, a fluid loss control agent, and anemulsifier.

More particularly, the drilling fluid compositions may includeXanthomonas campestris (XC) polymer (xanthan gum). Xanthan gum may beadded to improve the cutting transportation and rheology of the drillingfluids, or to avoid filtrate loss. Xanthan gum is a polysaccharidedischarged by the bacteria called Xanthomonas campestris. Chemically,Xanthum gum includes the calcium, potassium, and sodium salt of a highermolecular weight polysaccharide. These polysaccharides containd-glucuronic, d-glucose, and d-mannose acid. Xanthan gum is completelysoluble in water and in solid form has a color of cream powder. Xanthangum contains at least 1.5% (by weight) pyruvic acid.

The drilling fluid compositions may include caustic soda as apH-adjuster to maintain the pH of the drilling fluid. The drilling fluidcompositions may also include sodium chloride as a clay stabilizationadditive. The drilling fluid compositions may also include starch, forexample, hydroxypropyl starch, which is a derivative of natural starch,to avoid fluid loss. The starch may be nonionic and may only be affectedby hardness and salinity of the fluids. The drilling fluid compositionsmay also include calcium carbonate (CaCO₃) with two differentmicron-sized particles as a bridging agent. The drilling fluidcompositions may also include calcium chloride as a clay stabilizationadditive. When present, these components are in a range of from about0.01 to about 5 wt % (weight percent), such as from 0.5 to 3 wt %, suchas from 0.8 to 2 wt % relative to a total weight of the drilling fluidcomposition.

The method for reducing a filter cake from a wellbore surface in asubterranean formation according to one or more embodiment may includeintroducing into the wellbore the drilling fluid composition having aweighting agent and encapsulated thermochemicals. The thermochemicalsmay include a nitrite-containing compound and an ammonium-containingcompound that are encapsulated together in copolymer micro-particles. Asa result, the drilling fluid composition may be in contact with thewellbore surface and a filter cake may be formed on the surface of thewellbore.

The method may include maintaining the drilling fluid composition in thewellbore such that the drilling fluid composition reaches a temperaturesufficient for the encapsulated thermochemicals to react, where thereaction of the encapsulated thermochemicals generates heat and nitrogengas. As a result, at least a portion of the formed filter cake may beremoved using the heat and nitrogen gas released from the reaction ofthe thermochemicals. The method may further include forming the drillingfluid composition before introducing the drilling fluid composition intothe wellbore. The method may further include cementing the wellboreafter the step of removing at least a portion of the formed filer cake.The method may further include producing hydrocarbons after the step ofremoving at least a portion of the formed filer cake.

Using the method according to one or more embodiments, at least 70 vol %(volume percent), or at least 75 vol %, or at least 80 vol %, or atleast 85 vol % of a filter cake formed on the surface of a formationface may be removed. The method may also provide for the removal of in arange of from about 70 vol % to about 99 vol % of the filter cake formedon the surface on a formation face, or from about 71 vol % to about 99vol %, or from about 72 vol % to about 98 vol %, or from about 73 vol %to about 97 vol %, or from about 74 vol % to about 96 vol %, or fromabout 75 vol % to about 95 vol %, or from about 76 vol % to about 94 vol%, or from about 77 vol % to about 93 vol %, or from about 78 vol % toabout 92 vol %, or from about 79 vol % to about 91 vol %, or from about80 vol % to about 90 vol %, or from about 85 vol % to about 90 vol %.

Using the encapsulated thermochemicals may generate heat and highpressure through exothermic reactions within the wellbore once theencapsulated thermochemicals reach a certain temperature and once theencapsulating copolymer micro-particles are decomposed. In one or moreembodiment methods, the encapsulated thermochemicals are part of thedrilling fluid pumped into the wellbore. The system may be controlled byusing specific copolymer micro-particles sizes and thicknesses. Theencapsulation can be uniformly sized microporous tubular membrane withan average micropore diameter in the range of from about 0.1 to about 30μm, or from about 0.5 to about 25 μm, or from about 1 to about 20 μm, orfrom about 5 to about 10 μm.

In addition, the encapsulated thermochemicals start a thermochemicalreaction when they reach a certain temperature within the wellbore. Thisactivating temperature may depend on the type of thermochemicals beingused, and may be, for example, greater than about 25° C., greater thanabout 50° C., or greater than about 70° C. Therefore, the start of thethermochemical reaction may depend on temperature within the wellbore.Additionally, the start of the thermochemical reaction may depend onother wellbore conditions, such as pH and pressure. The thermochemicalreaction releases kinetic and thermal energy, which helps remove thefilter cake that is deposited on the face of the formation when thedrilling fluid is added. Therefore, the method results in theself-destruction of filter cake that is formed from the barite containedin the drilling fluid and removed by the thermochemical reaction of thethermochemical compounds contained in the same drilling fluid.

EXAMPLES

The following examples are merely illustrative and should not beinterpreted as limiting the scope of the present disclosure.

Example 1—Reaction Kinetics

The reaction kinetics of the thermochemical reaction of Equation (1)were investigated.

$\begin{matrix}\left. {{{NH}_{4}{Cl}} + {NaNO}_{2}}\rightarrow\begin{bmatrix}{{{NH}_{4}{NO}_{2}} + {{{NaCl}.{NH}_{4}}{NO}_{2}}} \\{Themolabile}\end{bmatrix}\rightarrow{{NaCl} + {2H_{2}0} + {N_{2}({gas})} + {\Delta{H({heat})}}} \right. & (1)\end{matrix}$

The reaction parameters, such as enthalpy change, thermal conductivity,and specific heat capacity, were determined. These parameters, whichwere determined to produce the thermal energy required to dissolvefilter cake formed with water and oil-based drilling fluids, are listedin Table 1. Enthalpy change is in kJ/mol is Kilojoules per mole, thermalconductivity is in Watts per mole-Kelvin, and specific heat capacity isin Joules per mole-Kelvin.

TABLE 1 Reaction parameters obtained from the thermochemical reactionNH₄Cl and NaNO₂ in one molar concentration Reaction Parameters ValuesUnits Enthalpy change (ΔH) 369 kJ/mol Thermal conductivity (λ) 0.1-0.6W/m · K Specific heat capacity (C)  85-110 J/mol · K

The thermochemical reaction of Equation (1) generated a temperature ofup to 371° C. and pressure up to 3500 psi (pounds per square inch). Thepressure pulse generation profiles were also determined for one molarand two molar solution ratio concentrations of the thermochemicalreactants. The thermochemical reactions were initiated by preheating acell to 100° C. The generated pressure pulses from the release ofnitrogen gas were logged in an aging cell with a capacity of 20 cc(cubic centimeters). The corresponding pressure pulse generationprofiles are illustrated in FIG. 1 . FIG. 1 shows that increasing themolar concentration of the thermochemical reactants enhanced thepressure generation.

The thermochemical reaction was studied under batch system in aninsulated micro-reactor. The schematic of the set-up is shown in FIG. 3. It consists of a high temperature/high-pressure (HTHP) micro-reactor,nitrogen gas cylinder, heater, and sensors (for temperature and pressuremeasurement) coupled with a computer processor. Certain volumes ofequimolar concentrations of the reactants (ammonium chloride and sodiumnitrite) were fed into the reactor. The reaction was performed atdifferent reactor temperatures (50, 60, 70, 80, 90, 100° C.: typical ofrepresentative reservoir temperatures) with the reactants (pH=5.8,molarity (M)=1). The progress was monitored by collecting data forincrease in temperature and pressure at equal time intervals through thedata logging system. The nitrogen gas generated during the reactionsproduced the pressure increase of the system. The pressure generated inthe system was logged and reported.

In addition, FIG. 2 shows the sensitivity of the initial wellboretemperature on the reaction time. FIG. 2 shows test results for varyinginitial wellbore temperatures from 50° C. to 100° C. using one molar andtwo molar concentrations ratios of the thermochemical reactants ofEquation (1). As shown in FIG. 2 , the reaction time of thermochemicalfluids strongly correlates with the initial wellbore temperature.

Example 2— Water-Based and Oil-Based Drilling Fluid Formulations withand without Thermochemicals

Examples of water-based and oil-based drilling fluid compositions wereprepared according to the formulations shown in Tables 2 and 3,respectively. An emulsion-based microencapsulation technique was usedfor encapsulation. Removal precursors were developed by encapsulatingthe formulation in polymeric shells that decomposes at a controlled timeat a specific temperature to remove the barite filter cake. This can bedone for oil and water-based drilling fluids. The encapsulation processwas achieved using membrane technology. With this technology, a highdegree of capsule-size uniformity could be obtained with low energyinput and reduced material consumption.

Table 2 shows water-based drilling fluid formulations with(Experiment 1) and without (Comparative Example 1) encapsulatedthermochemicals. Distilled water was used as a base fluid in bothformulations. Comparative Example 1 represents a conventionalwater-based drilling fluid system commonly used in the industry.Experiment 1 included the two types of encapsulated thermochemicalfluids. In both formulations, barite particles were the main constituentof the drilling fluid system. Barite particles weighing 278 g (grams)out of total solids weight (552 to 566) g comprising a weightage of 50%of the total solids. Xanthan gum was added to both formulations toimprove the cutting transportation rheology of the drilling fluids, andto avoid filtrate loss. Caustic soda was added in both formulations ofwater-based drilling fluids to maintain the pH of the drilling fluid.Calcium carbonate (CaCO₃) with two different micron-sized particles wasused as a bridging agent. Sodium chloride (NaCl) was used as a claystabilization additive. Hydroxypropyl starch, which is a derivative ofnatural starch, was added in both formulations of the drilling fluidsystem to avoid fluid loss. The starch is nonionic and can only beaffected by hardness and salinity of the fluids. In Experiment 1 of thewater-based drilling fluid, the amounts of encapsulated thermochemicalfluids TCFA (NH₄Cl+NaNO₂) and TCFB (NH₄Cl+NaNO₂ at twice the molarsolution ratio of TCFA), added were 8.5 g and 5.5 g, respectively. Theencapsulated size of the pills was in between 25 to 50 microns.

TABLE 2 Water-based drilling fluid formulations Chemical ExperimentComparative Components Formula 1 Example 1 Units Distilled Water H₂O241.5 241.5 cm³ Xanthomonas Campestris 1 1 G (XC) Polymer (xanthan gum)Caustic Soda NaOH 0.25 0.25 g Sodium Chloride NaCl 22 22 g Starch(hydroxypropyl) C₆H₅0₁₀ 4 4 g Calcium Carbonate CaCO₃ 3 3 G CaCO3 (25micron) Calcium Carbonate CaCO₃ 3 3 G CaCO3 (38 micron) Barite (60micron) BaSO₄ 278 278 G Encapsulated TCFA NH₄Cl + 5.5 0 G (25 to 50micron) NaNO₂ Encapsulated TCFB NH₄Cl + 8.5 0 G (25 to 50 micron) NaNO₂

Two oil-based drilling fluid Experiment 2 and Comparative Example 2 arealso prepared and are shown in Table 3. In these oil-based drillingfluid formulations, diesel was used as base fluid. An emulsifier wasadded in both formulations of oil-based drilling fluids to reduce theinterfacial tension between oil and water. Gemini type surfactants wereused as emulsifiers. This ensured the formation of stable and smallwater droplets. Calcium chloride (CaCl₂)) was used as a claystabilization additive in both formulations of oil-based drillingfluids. In Experiment 2, the amounts of encapsulated thermochemicalfluids TCFA and TCFB added were 8.5 g and 5.5 g, respectively. Theencapsulated size of the pills was between 25 to 50 microns.

TABLE 3 Oil-based drilling fluids formulations Chemical ExperimentComparative Components Formula 2 Example 2 Unit Diesel 172 172 cm³Emulsifier 11 11 G Water H₂O 50 50 cm³ Calcium chloride CaCl2 32 32 gBarite (40-60 micron) BaSO₄ 300 300 g Encapsulated TCFA NH₄Cl + 5.5 0 g(25 to 50 micron) NaNO₂ Encapsulated TCFB NH₄Cl + 8.5 0 g (25 to 50micron) NaNO₂

Example 3—HPHT Filter Press Experiments

To create and remove the filter cake using water-based and oil-baseddrilling fluid compositions according to the examples, ahigh-temperature/high-pressure (HPHT) static filter press apparatus wasused. FIG. 3 is a schematic representation of the HPHT static filtersystem 100 that was used in the Examples. The HPHT static filter system100 has a canister 101 containing compressed nitrogen gas and aregulator 102. In the HPHT static filter system 100, the nitrogen gas103 is pushed in the heating jacket 104 containing the drilling fluid105 and formed filter cake 106 over a rock sample 107. The drillingfluid filtrate 108 is weighed using balance 109.

The tests were conducted at the pressure differential of 200 psi andambient temperature. To create and remove the filter cake using old andnew formulations, the HPHT API static (American Petroleum Institute)filter press apparatus was used. All the tests were carried out at thepressure difference of 200 psi and ambient temperature. The API filterpress is shown in FIG. 3 . The filter cake was formed on a ceramic disk.The diameter of the ceramic disk was 25 mm (milimeters). The thicknessof the ceramic disk was 1.3 mm. Four different experiments wereperformed using the oil and water-based drilling fluids ComparativeExamples 1-2 and Examples 1-2. The formed filter cake was placed in anHPHT cell and heated up to 100° C. for 48 hours as a soaking time. Adifferential pressure of 200 psi was applied. The weight of the filtercake before and after the treatment was recorded.

Example 4— Rheological Properties of Drilling Fluids

The basic drilling fluid properties of the drilling fluid of ComparativeExamples 1-2 and Experiments 1-2 mud are shown in FIGS. 4 and 5 . Basicdrilling fluid properties measured were density, plastic viscosity,yield point, 10 sec gel strength, 10 min gel strength, and pH. Asillustrated in FIGS. 4 and 5 , it can be observed that basic drillingfluid properties were not affected by the presence of encapsulatedthermochemicals in the drilling fluids. As such, these encapsulatedthermochemicals can be considered compatible with the drilling fluidingredients.

Example 5—Static Filtration Experiments

API static filtration experiments (API RP 13B-1, 5th Edition, May2019—Recommended Practice for Field Testing Water-based Drilling Fluids)were conducted using a Fann filter press apparatus for the formulationsof oil-based and water-based drilling fluids.

FIG. 6 shows the filtration performances of the formulations ofExperiment 1 and Comparative Example 1 on a ceramic disk. The resultsshown in FIG. 6 are of standard test time of 30 minutes. The water-baseddrilling fluid of Comparative Example 1 yielded a total filtrate volumeof 9.7 cm³ (cubic centimeters). The filter cake formed on a ceramic dischad a thickness of 1.3 mm. The water-based drilling fluid of Experiment1 yielded a filtrate volume of 9.5 cm³ after 30 minutes of the test. Thefilter cake formed on a ceramic disk had a thickness of 1.2 mm.

FIG. 7 shows the filtration performances of oil-based drilling fluids ofExperiment 2 and Comparative Example 2. Comparative Example 2 resultedin the filtrate loss of 5.1 cm³, while Experiment 2 resulted in thefiltrate loss of 5.2 cm³.

The filtration of water-based and oil-based drilling fluid formulationswith encapsulated thermochemicals (Experiments 1 and 2) was almostidentical with that of water- and oil-based drilling fluid formulationswithout encapsulated thermochemicals (Comparative Examples 1 and 2),respectively. The filtration of water-based and oil-based drilling fluidformulations with encapsulated thermochemicals was almost identical withthat of water- and oil-based drilling fluid formulations withoutencapsulated thermochemicals. The ratio used in the Examples can beoptimized based on the formation rock pore throat distribution. Thethermochemicals capsule size should be comparable with the formationrock pore throat size distribution.

The filter cake formed using the formulations of water-based andoil-based drilling fluids with and without encapsulated thermochemicalsare shown in FIG. 8 . The removal efficiency in the case of water-baseddrilling fluid was 70% by taking the weight difference between theoriginal weight and final weight of the filter cake. The original weightmeans the weight of the filter cake with old drilling formulations andthe final weight means the weight of the drilling fluids with thethermochemical formulation. This confirmed that the encapsulatedthermochemicals were an integral part of the filter cake. Once thethermochemical reaction took place, the generated pressure andtemperature disturbed the filter cake and removed the majority of thesolids from the surface to become part of the bulk drilling fluid. Infield operations, the efficiency is expected to be greater because theencapsulated thermochemicals, once reacted, will generate potentiallyincreased pressure that will push back most of the solids remaining fromthe filter cake.

The removal efficiency of the oil-based formulation of Experiment 2 was85%. In field conditions, this efficiency is expected to be potentiallygreater because of the generated pressure and temperature from theencapsulated thermochemicals that invaded the formation.

The thickness of the filter cake formed with the water- and oil-baseddrilling fluids formulations were measured. The thickness of filter cakeformed on a ceramic disk with water-based drilling fluid of ComparativeExperiment 1 was 0.45 mm. The thickness of filter cake formed on aceramic disk with water-based drilling fluid of Experiment 1 was 1.7 mm.The thickness of filter cake formed on a ceramic disk with oil-baseddrilling fluid of Experiment 2 was 0.25 mm. The thickness of filter cakeformed on a ceramic disk with oil-based drilling fluid of ComparativeExample 2 was 1.3 mm.

Example 5— Thermochemical Stability Experiments

FIG. 9 shows the time stability of encapsulated thermochemicals and thegeneration of pressure and temperature due to the exothermic reactiongenerated from the thermochemical reaction shown in Equation (1). Thetime stability of the encapsulated thermochemicals was 48 hours. It isnoted that in drilling operations, at least 48 hours are usually neededfor the trip in and trip out before moving into cementing operations.After 48 hours, the strongly exothermic reaction initiated, andthermochemical fluids reacted. Upon reaction, the pressure increasedfrom 200 psi to 1100 psi. The temperature increased from 100° C. to 180°C. The microcapsules encapsulating the thermochemicals were stablealmost for 2 days.

In comparison, FIG. 10 shows the pressure and temperature generated fromthe same thermochemicals that are non-encapsulated. In this comparativeexample, the temperature of the reactor was 100° C., and the reactiontook place in less than 2 min compared to the 2 days for theencapsulated thermochemicals. The generated pressure and temperature arecomparable with those obtained in the case of encapsulatedthermochemicals. The kinetics of the thermochemical reaction wereexamined in a micro-reactor system. The reaction kinetics parameterswere determined to produce the thermal energy required to dissolvefilter cake formed with water and oil-based drilling fluids. Thethermochemical reaction was triggered by preheating a micro-reactorsystem to 100° C. The molar ratio of reactants was 1:1.

One of the major challenges that operators face when using conventionalmethods of hydrocarbon recovery of tight and high stress reservoirsincludes hydrocarbon losses resulting from high breakdown pressuresexceeding pumping limitation or completion rating. Advantageously, theoil-based and water-based drilling fluids formulations includingencapsulated thermochemicals of this disclosure resulted in theself-destruction of filter cake formed with oil-based and water-baseddrilling fluids. In addition, the thickness of filter cake obtainedusing the present formulations may be much thinner, as measured at 0.6mm and 0.5 mm, than filter cake formed in conventional operations, asmeasured at 1.7 mm and 1.3 mm, respectively, in the correspondingExamples.

While only a limited number of embodiments have been described, thoseskilled in the art having benefit of this disclosure will appreciatethat other embodiments can be devised which do not depart from the scopeof the disclosure.

Although the preceding description has been described here withreference to particular means, materials and embodiments, it is notintended to be limited to the particulars disclosed here; rather, itextends to all functionally equivalent structures, methods and uses,such as those within the scope of the appended claims.

The presently disclosed methods and compositions may suitably comprise,consist or consist essentially of the elements disclosed and may bepracticed in the absence of an element not disclosed. For example, thoseskilled in the art can recognize that certain steps can be combined intoa single step.

Unless defined otherwise, all technical and scientific terms used havethe same meaning as commonly understood by one of ordinary skill in theart to which these systems, apparatuses, methods, processes, andcompositions belong.

The ranges of this disclosure may be expressed in the disclosure as fromabout one particular value, to about another particular value, or both.When such a range is expressed, it is to be understood that anotherembodiment is from the one particular value to the other particularvalue, or both, along with all combinations within this range.

The singular forms “a,” “an,” and “the” include plural referents, unlessthe context clearly dictates otherwise.

As used here and in the appended claims, the words “comprise,” “has,”and “include” and all grammatical variations thereof are each intendedto have an open, non-limiting meaning that does not exclude additionalelements or steps.

The terms substantial, “substantially”, and all grammatical variationsthereof as used refers to a majority of, or mostly, as in at least about50%, 60%, 70%, 80%, 90%, 95%, 96%, 97%, 98%, 99%, 99.5%, 99.9%, 99.99%,or at least about 99.999% or more.

Although only a few example embodiments have been described in detailabove, those skilled in the art will readily appreciate that manymodifications are possible in the example embodiments without materiallydeparting from this invention. Accordingly, all such modifications areintended to be included within the scope of this disclosure as definedin the following claims. In the claims, any means-plus-function clausesare intended to cover the structures described herein as performing therecited function(s) and equivalents of those structures. Similarly, anystep-plus-function clauses in the claims are intended to cover the actsdescribed here as performing the recited function(s) and equivalents ofthose acts. It is the express intention of the applicant not to invoke35 U.S.C. § 112(f) for any limitations of any of the claims herein,except for those in which the claim expressly uses the words “means for”or “step for” together with an associated function.

1. A drilling fluid composition comprising: a weighting agent; anitrite-containing compound; and an ammonium-containing compound; wherethe nitrite-containing compound and the ammonium-containing compound areencapsulated together in copolymer micro-particles forming encapsulatedthermochemical compounds, where the copolymer micro-particles are stablefor at least 48 hours, and where at least one property selected from thegroup consisting of the density, the plastic viscosity, the yield point,the gel strength, and the pH of the drilling fluid composition issubstantially similar to the at least one property of a comparabledrilling fluid composition devoid of the encapsulated thermochemicalcompounds.
 2. The drilling fluid of claim 1, where the weighting agentis barium sulfate.
 3. The drilling fluid of claim 2, where the bariumsulfate comprises barium sulfate particles having a size in a range ofabout 40 microns to about 60 microns.
 4. The drilling fluid of claim 1,where the nitrite-containing compound is sodium nitrite.
 5. The drillingfluid of claim 1, where the ammonium-containing compound is ammoniumchloride.
 6. The drilling fluid of claim 1, where theammonium-containing compound is ammonium sulfate.
 7. The drilling fluidof claim 1, where the drilling fluid composition is a water-baseddrilling fluid.
 8. The drilling fluid of claim 1, where the drillingfluid composition is an oil-based drilling fluid.
 9. The drilling fluidof claim 1, further comprising one or more additives selected from thegroup consisting of rheology modifiers, pH-adjusters, clay stabilizers,bridging agents, fluid loss control agents, and emulsifiers.
 10. Thedrilling fluid of claim 1, where the copolymer micro-particles have asize in a range of about 25 to about 50 microns.
 11. The drilling fluidof claim 1, where the encapsulated thermochemical compounds are presentin the drilling fluid in an amount of about 1 wt % to about 15 wt %based on the total weight of the drilling fluid.
 12. A method forreducing a filter cake from a wellbore surface in a subterraneanformation, the method comprising: introducing into the wellbore adrilling fluid composition comprising a weighting agent, anitrite-containing compound, and an ammonium-containing compound, wherenitrite-containing compound and the ammonium-containing compound areencapsulated together in copolymer micro-particles forming encapsulatedthermochemical compounds; and allowing the drilling fluid composition toreach a temperature in the wellbore sufficient for the encapsulatedthermochemical compounds to react, where the reaction of theencapsulated thermochemical compounds generates heat and nitrogen gas;and where at least a portion of the formed filter cake is removed usingthe heat and nitrogen gas released from the reaction of thethermochemical compounds.
 13. The method of claim 12, where at least 70vol % of the formed filter cake is removed.
 14. The method of claim 12,further comprising forming the drilling fluid composition beforeintroducing it into the wellbore.
 15. The method of claim 12, furthercomprising cementing the wellbore after the step of removing at least aportion of the formed filer cake.
 16. The method of claim 12, furthercomprising producing hydrocarbons after the step of removing at least aportion of the formed filer cake.